Removing Contaminants from Natural Gas

ABSTRACT

A process is described for removing contaminants from a natural gas feed stream including water. The process includes the steps of cooling the natural gas feed stream in a first vessel to a first operating temperature at which hydrates are formed, heating the hydrates to a temperature that is above the first operating temperature by introducing a warm liquid to the first vessel so as to melt the hydrates and liberate a dehydrated gas and a water-containing liquid, and removing from the first vessel a stream of dehydrated gas.

RELATED APPLICATIONS

This application claims priority to co-pending U.S. patent applicationSer. No. 10/772,621, filed Feb. 5, 2004, which claims priority toAustralian patent application having serial number 2003900534, filedFeb. 7, 2003. Co-pending U.S. application Ser. No. 10/772,621 is hereinincorporated by reference in its entirety.

FIELD OF INVENTION

The present invention relates to a process for removing a contaminantfrom a natural gas feed stream.

BACKGROUND

Natural gas from either production reservoirs or storage reservoirstypically contains water, as well as other species, which form solidsduring the liquefaction to produce liquefied natural gas (LNG). It iscommon practice for the natural gas to be subjected to a dehydrationprocess prior to the liquefaction. Water is removed to prevent hydrateformation occurring in pipelines and heat exchangers upstream of theliquefaction vessel.

If water is not removed, solid hydrates may form in pipe work, heatexchangers and/or the liquefaction vessel. The hydrates are stablesolids comprising water and natural gas having the outward appearance ofice, with the natural gas stored within the crystal lattice of thehydrate.

The formation of natural gas hydrates was historically seen as anundesirable result that should be avoided. However, processes have beendeveloped to encourage natural gas hydrate formation such asInternational patent applications No. 01/00 755 and No. 01/12 758. Inthe first of these International patent applications, a method andapparatus is described whereby natural gas and water are combined in thepresence of an agent adapted to reduce the natural gas water interfacialtension to encourage natural gas hydrate formation. In the second ofthese International patent applications, a production plant isdescribed, including a convoluted flow path to cause mixing of water andnatural gas as a first step prior to reducing the temperature to producenatural gas hydrate.

Methods of dehydrating natural gas feed streams include absorption ofwater in glycol or adsorption of the water using a solid such ashydrated aluminium oxide, silica gels, silica-alumina gels and molecularsieves.

Natural gas also typically contains sour species, such as hydrogensulphide (H₂S) and carbon dioxide (CO₂). Such a natural gas isclassified as “sour gas”. When the H₂S and CO₂ have been removed fromthe natural gas feed stream, the gas is then classified as “sweet”. Theterm “sour gas” is applied to natural gases including H₂S because of thebad odour that is emitted even at low concentrations from an unsweetenedgas. H₂S is a contaminant of natural gas that must be removed to satisfylegal requirements, as H₂S and its combustion products of sulphurdioxide and sulphur trioxide are also toxic. Furthermore, H₂S iscorrosive to most metals normally associated with gas pipelines so thatprocessing and handling of a sour gas may lead to premature failure ofsuch systems.

Gas sweetening processes typically include adsorption using solidadsorption processes or absorption using amine processes, molecularsieves, etc. Existing dehydration and gas sweetening processes areextremely complex and expensive.

SUMMARY OF THE INVENTION

A process for removing contaminants from a natural gas feed streamcontaining water is provided comprising the steps of: cooling thenatural gas feed stream in a first vessel to a first operatingtemperature at which hydrates are formed; and removing from the firstvessel a stream of dehydrated gas.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic process flow diagram of one embodiment of theinvention.

FIG. 2 is a schematic process flow diagram of a further embodiment ofthe invention.

DETAILED DESCRIPTION OF THE INVENTION

The present invention represents an improvement on the process anddevice discussed in International patent application publication No.03/062 725.

Contaminants from a natural gas feed stream is removed by forming asolid of the contaminant and suitably subsequently melting the solidcontaminant.

When the contaminant is water, one embodiment of the present inventionrelates to a process for dehydrating a natural gas feed stream.

When the contaminant is a sour species, for example hydrogen sulphide orcarbon dioxide, one embodiment of the present invention relates to aprocess for sweetening the natural gas feed stream.

In another embodiment of the present invention relates to a process forsequentially dehydrating and sweetening the natural gas feed stream.

To this end the process for removing contaminants from a natural gasfeed stream including water according to the present invention comprisesthe steps of cooling the natural gas feed stream in a first vessel to afirst operating temperature at which hydrates are formed; and removingfrom the first vessel a stream of dehydrated gas.

An essential feature of the process of the present invention is that onpurpose hydrates are formed in order to remove water. Normally formationof hydrates is prevented.

When the natural gas feed stream further includes sour species, theprocess according to the present invention suitably further comprisesthe steps of cooling the dehydrated gas in a second vessel to a secondoperating temperature at which solids of the sour species are formed orat which the sour species dissolve in a liquid; and removing from thesecond vessel a stream of dehydrated sweetened gas.

The term “operating temperature” is used to refer to a temperature belowthe solid/liquid transition temperature for the contaminant at a givenpressure of operation of the first or second vessel.

In this specification a “warm” liquid stream can be any compatiblestream of liquid having a temperature above the solid/liquid transitiontemperature of the contaminant for a given pressure of operation of thefirst or second vessel. The warm liquid stream has thus a temperaturethat is sufficiently high to cause melting of the solids of thecontaminant. The warm liquid may or may not take the contaminant fullyinto solution.

The invention will now be described in more detail with reference to theaccompanying drawings.

Reference is now made to FIG. 1. FIG. 1 shows an apparatus 10 forcarrying out the process of the present invention. The apparatus 10comprises a first vessel 12. The contaminant removed in the first vessel12 is water and thus the gas exiting the first vessel 12 is dry. Alsoheavy hydrocarbons are removed as a consequence of this process, andthus the gas stream exiting the first vessel 12 is dew pointed forhydrocarbons to an extent determined by the conditions in the firstvessel 12. The water dew point of the gas exiting the first vessel 12,however, is lower than its equilibrium dew point due to the formation ofhydrates.

In the embodiment as illustrated in FIG. 1, wet feed gas from a wellheadis fed through conduit 15 to a first flash tank 16 in which condensateis separated from the feed gas. The pressure and temperature conditionswithin the first flash tank 16 would typically be in the order of 75 to130 bar and between 25 and 40 degrees C. (about 5 to 10 degrees C. abovethe hydrate formation temperature). The condensate liquid stream exitingthe first flash vessel 16 through conduit 17 is “a warm liquid” asdefined above. The condensate consists of liquid hydrocarbons that areproduced together with natural gas. The gas stream separated from thesour wet feed gas in the first flash tank 16 enters the first vessel 12via wet sour gas feed stream inlet 20. An intermediate heat exchanger 22may be used to cool the wet sour gas between the first flash tank 16 andthe first vessel 12. The intermediate heat exchanger 22 drops thetemperature of the wet sour gas to a temperature just above the hydrateformation temperature for the particular pressure of this feed stream.The hydrate formation temperature for the particular pressure of thefeed stream is the maximum value of the first operating temperature,which is the operating temperature in the first vessel 12.

The wet gas feed stream fed to the first vessel 12 is expanded using aJoule-Thompson valve 24 or other suitable expansion means such as aturbo expander to further cool the stream as it enters the first vessel12. The Joule-Thompson valve 24 may alternatively define the inlet 20 tothe first vessel 12. Upon expansion of the wet sour gas feed stream intothe first vessel 12, the gas pressure-temperature conditions within thevessel 12 allow hydrates to form. The necessary degree of cooling isachieved by the degree of expansion of the wet sour gas feed streamthrough the Joule-Thompson valve 24.

The first operating temperature and the pressure in the first vessel 12are maintained at a level whereby hydrates are formed. The natural gasfeed stream entering downstream of the Joule-Thompson valve 24 into thefirst vessel 12 is at the first operating temperature.

If the natural gas feed stream also contains sour species, the firstoperating temperature to which the feed gas in the first vessel 12 iscooled is below the temperature at which hydrates are formed but abovethe temperature at which solids of sour species, such as H₂S and CO₂,are formed. This is done to produce hydrates and to prevent theformation of solids of sour species in the first vessel 12.

Dry sour gas exits the first vessel 12 via dry sour gas outlet 34.Typically the dry sour gas exiting the first vessel 12 would have anominal pressure of 10 to 30 bar lower than the pressure upstream of theexpansion device 24 and a temperature of 10 to 25 degrees C. lower thanthe temperature just upstream of the expansion device 24. The term “drygas” is used to refer to water-free gas.

A hydrate-containing liquid stream is removed from the first vessel 12via water condensate outlet 28, and passed through conduit 29 to aseparator 30. The water is separated from the condensate in the watercondensate separator 30. Such a separator is for example a baffledgravity separation unit. As water is heavier than the condensate, anysuitable gravity separation techniques may be used. The separatedcondensate is removed through conduit 31 and the separated water isremoved through conduit 33.

The natural gas feed stream entering into the first vessel 12 was cooledto the first operating temperature. Alternatively, the natural gas feedstream can be cooled using one or more sprays of a sub-cooled liquidintroduced via sub-cooled liquid inlet 26. In a further alternativeembodiment, the natural gas feed stream is cooled by both theJoule-Thompson valve 24 and the sub-cooled liquid supplied through inlet26. In case of spray cooling, the natural gas feed stream can enter intothe first vessel 12 at a temperature that is at or above thehydrate-formation temperature.

The sub-cooled liquid inlet 26 should be located in the first vessel 12above the inlet 20 of the wet sour gas feed stream. In the illustratedembodiment, the sub-cooled liquid inlet 26 is a plurality of spraynozzles. The particular sub-cooled liquid is condensate recycled fromthe process and sprayed into the first vessel 12. Sprays are used inorder to maximise the contact area of the sub-cooled liquid and the gasand thus the cooling effect of contact of the sub-cooled liquid with thewet-sour gas.

The dry sour gas at a pressure of 10 to 30 bar lower than the pressureupstream of the expansion device 24 and at the operating temperature ofthe first vessel 12 is directed via second heat exchanger 36 in conduit35 to a second flash tank 40. It is cooled in the second heat exchanger36 to form a two-phase mixture of gas and condensate at a temperaturehigher than −56 degrees C. Not shown is that additional cooling may beprovided by indirect heat exchange with a refrigerant that is circulatedthrough an external refrigeration cycle, for example a propanerefrigeration cycle. In the second flash tank 40, condensate isseparated from the dry sour gas stream. The liquid stream exits thesecond flash tank 40 via liquid outlet 42 and is sufficiently cooled tosatisfy the criteria of a sub-cooled liquid that may be fed to thesub-cooled liquid inlet 26 of the first vessel 12. The sub-cooled liquidis supplied through conduit 43, provided with a pump 44 to thesub-cooled liquid inlet 26.

The dry sour gas exits the second flash tank 40 via gas outlet 47 and isfed through conduit 45 to the intermediate heat exchanger 22 and fromthere to an end user (not shown). Conduit 45 may comprise aJoule-Thompson valve 48.

As observed earlier, the present invention relates to dehydratingnatural gas by forming hydrates. To prevent hydrates from blockingoutlet 28 and conduit 29, the condensate present in the lower portion ofthe first vessel 12 is preferably heated. This is suitably done byintroducing a warm liquid into the first vessel 12 below the level atwhich the feed stream is introduced.

A portion of the stream of warm condensate separated in the first flashtank 16 is fed through conduit 17 and inlet 18 to the first vessel 12.The warm condensate is sufficiently warm to liquefy hydrate formed inthe first region of the first vessel 12. As the hydrates melt, the gastrapped in the hydrate lattice is liberated and the water goes intosolution with the condensate. In addition at least a portion of thecondensate separated in the water/condensate separator 30 can berecycled for use as the warm liquid used for heating the solids of thefreezable species in the first vessel 12 through conduit 37 (afterheating, not shown).

Any gas present within the water condensate separator may be recycled tothe first vessel 12. Alternatively or additionally, a portion of the gasseparated in the water/condensate separator 30 may be recycled to thewet sour gas feed stream entering the first vessel 12 via inlet 20.

Suitably the liquid that is sprayed into the first vessel through inlets26 is a natural gas liquid, which natural gas liquid is a mixture of C₂,liquefied petroleum gas components, C₃ and C₄ and C₅₊ hydrocarboncomponents.

Suitably, the warm liquid that is introduced into the first vesselthrough inlet 18 is also a natural gas liquid.

Reference is now made to FIG. 2 showing a further embodiment of thepresent invention. In this further embodiment dehydrated gas is treatedto remove sour components from it. The dehydration process is discussedwith reference to FIG. 1, and will not be repeated here. Parts havingthe same function as parts shown in FIG. 1 get the same referencenumeral.

The dry sour gas exits the second flash tank 40 via gas outlet 47 and isfed to a second vessel 14 via dry sour gas inlet 46. As with the firstvessel 12, the dry sour gas being fed to the second vessel 14 may beexpanded through a Joule-Thompson valve 48 or other suitable expansionmeans, such as a turbo expander, in order to further cool the gas. Asbefore with the first vessel 12, the Joule-Thompson valve may define thedry sour gas inlet 46. The temperature of the dry gas entering into thesecond vessel 14 is at a second operating temperature. The secondoperating temperature is the maximum temperature at which solids of thesour species are formed or the temperature at which the sour speciesdissolve in a liquid.

The gas exiting the second vessel 14 via outlet 62 is dehydrated andsweetened. The dry sweetened gas would typically be at a pressure ofbetween 20 and 50 bar and a temperature of not lower than −85.degree. C.This product stream of sweetened dry gas is typically transported to theend user at ambient temperature.

The product stream of dry sweetened gas can be further cooled byallowing the gas to expand in expansion device 63, and the furthercooled dry sweetened gas is used in one or more of the heat exchangers38, 36 or 22 to effect cooling of one or more of the other processstreams within the apparatus 10. Please note that the temperature towhich the dry gas is cooled in heat exchanger 36 is greater than that atwhich the solids of the sour species form for the given line pressure.

Through outlet 52 a liquid is removed that contains the sour species.

The dry sour gas was cooled to the second operating temperature byallowing the gas to expand in Joule-Thompson valve 48. Alternatively,the dry sour gas can be cooled using one or more sprays of a sub-cooledliquid supplied through inlet 49. In a further alternative embodiment,the natural gas feed stream is cooled by both the Joule-Thompson valve48 and the sub-cooled liquid supplied through inlet 49. In case of spraycooling, the dry gas can enter into the second vessel 14 at atemperature that is at or above the temperature at which solids of thesour species are formed or the temperature at which the sour speciesdissolve in a liquid.

The sub-cooled liquid inlet 49 should be located in the second vessel 14above the dry sour gas inlet 46. In the illustrated embodiment thesub-cooled liquid inlet 49 is a plurality of spray nozzles. Thetemperature and pressure conditions in the second vessel 14 are adjustedso as to form solids of the freezable species. For sweetening of a gas,the temperature-pressure conditions need only be adjusted to form solidsof hydrogen sulphide (H.sub.2S) and carbon dioxide (CO.sub.2). However,the process conditions within the second vessel are sufficient to causethe formation of solids of the freezable species of other hydrocarbonssuch as benzene, toluene, ethylbenzene and xylene.

Suitably, the sub-cooled liquid is part of the liquid passing throughconduit 43. In order to reduce the temperature the liquid is passedthrough conduit 50 to the heat exchanger 38 where it is cooled byindirect heat exchange with dry sweetened gas. The dry sweetened gas isthen passed through conduit 65 to heat exchanger 36 for cooling the drysour gas from the first vessel 12. The dry sweetened gas is then fed tothe intermediate heat exchanger 22 and from there to an end user (notshown).

Applicant had found that in particular the concentration of C₂-C₄hydrocarbon components in the liquid should be in the range of from 0.5to 1.5 mol per mol of CO₂ in the feed gas. The liquid in the secondvessel 14 is the liquid sprayed in the vessel through the inlet 49. Thusthe concentration of C₂-C₄ hydrocarbon components in the sub-cooledliquid should be in the specified range. It will be understood that ifthe concentration of C₂-C₄ hydrocarbon components in the liquid streamin conduit 50 is too low, additional C₂-C₄ hydrocarbon components can beadded to this stream.

To prevent sour species from blocking outlet 52, the condensate presentin the lower portion of the second vessel 14 is preferably heated. Thisis suitably done by introducing a warm liquid through warm condensateinlet 56 into the second vessel 14 below the level at which the feedstream is introduced. A suitable liquid is liquid passing throughconduit 50. Alternatively liquid passing through conduit 31 can be used.

Further optimization of the above discussed flow schemes to improve heatintegration is possible. For example part of the hydrocarbon liquidstream leaving the second vessel 14 through outlet 52 can be recycled toinlet 26 of the first vessel 12. In order to do so a separation vessel(not shown) is used to separate a stream of liquid enriched in sourspecies from the hydrocarbon stream that is recycled.

Those of skill in the art will appreciate that many modifications andvariations are possible in terms of the disclosed embodiments,configurations, materials and methods without departing from theirspirit and scope. Accordingly, the scope of the claims appendedhereafter and their functional equivalents should not be limited byparticular embodiments described and illustrated herein, as these aremerely exemplary in nature.

1. A process for removing contaminants from a natural gas feed streamincluding water, which process comprises the steps of: cooling thenatural gas feed stream in a first vessel to a first operatingtemperature at which hydrates are formed; and, heating the hydrates to atemperature that is above the first operating temperature by introducinga warm liquid to the first vessel so as to melt the hydrates andliberate a dehydrated gas and a water-containing liquid; and, removingfrom the first vessel a stream of dehydrated gas.
 2. The process ofclaim 1, wherein the warm liquid is a natural gas liquid.
 3. The processof claim 2, further comprising the step of separating natural gasliquids from the natural gas feed stream upstream of the first vesseland using the separated natural gas liquid as the warm liquid introducedto the first vessel to melt the hydrates.
 4. The process of claim 1,further comprising the step of removing the water-containing liquid fromthe first vessel and recovering natural gas liquids from thewater-containing liquid.
 5. The process of claim 4, wherein the naturalgas liquids recovered from the water-containing liquid are heated andrecycled as the warm liquid introduced to the first vessel to melt thehydrates.
 6. The process of claim 1, wherein the step of cooling thenatural gas feed stream in a first vessel to a first operatingtemperature comprises introducing the natural gas feed stream into thefirst vessel at a temperature that is below the first operatingtemperature.
 7. The process of claim 1, wherein the step of cooling thenatural gas feed stream comprises expanding the natural gas feed streamthrough an expansion device.
 8. The process of claim 1, wherein the stepof cooling the natural gas feed stream in a first vessel to a firstoperating temperature comprises introducing a sub-cooled liquid into thefirst vessel in addition to introducing the natural gas feed stream tothe first vessel, the sub-cooled liquid being introduced at atemperature that is below the first operating temperature.
 9. Theprocess of claim 8, wherein the first vessel includes an inlet for thenatural gas feed stream and the sub-cooled liquid is introduced througha sub-cooled liquid inlet located in the first vessel above the inletfor the natural gas feed stream.
 10. The process of claim 8, wherein thesub-cooled liquid is sprayed into the first vessel.
 11. The process ofclaim 8, wherein the sub-cooled liquid is a natural gas liquid.
 12. Theprocess of claim 11, further comprising the step of cooling thedehydrated gas removed from the first vessel to form a two-phase mixtureof gas and condensate at a temperature higher than −56° C. andseparating condensate from the two-phase mixture in a second flash tank.13. The process of claim 12, further comprising the step of recyclingthe separated condensate from the second flash tank as the sub-cooledliquid.
 14. The process of claim 1, wherein the natural gas feed streamfurther includes sour gas species, and the process further comprises thestep of sweetening the stream of dehydrated gas removed from the firstvessel by removal of the sour gas species.